1. Field of the Invention
The present invention relates to integrated oxidation processes to efficiently reduce the sulfur and nitrogen content of hydrocarbons to produce fuels having reduced sulfur and nitrogen levels.
2. Description of Related Art
The discharge into the atmosphere of sulfur compounds during processing and end-use of the petroleum products derived from sulfur-containing sour crude oil pose health and environmental problems. The stringent reduced-sulfur specifications applicable to transportation and other fuel products have impacted the refining industry, and it is necessary for refiners to make capital investments to greatly reduce the sulfur content in gas oils to 10 parts per million by weight (ppmw), or less. In industrialized nations such as the United States, Japan and the countries of the European Union, refineries for transportation fuel have already been required to produce environmentally clean transportation fuels. For instance, in 2007 the United States Environmental Protection Agency required the sulfur content of highway diesel fuel to be reduced 97%, from 500 ppmw (low sulfur diesel) to 15 ppmw (ultra-low sulfur diesel). The European Union has enacted even more stringent standards, requiring diesel and gasoline fuels sold in 2009 to contain less than 10 ppmw of sulfur. Other countries are following in the direction of the United States and the European Union and are moving forward with regulations that will require refineries to produce transportation fuels with an ultra-low sulfur level.
To keep pace with recent trends toward production of ultra-low sulfur fuels, refiners must choose among the processes or crude oils that provide flexibility to ensure that future specifications are met with minimum additional capital investment, in many instances by utilizing existing equipment. Conventional technologies such as hydrocracking and two-stage hydrotreating offer solutions to refiners for the production of clean transportation fuels. These technologies are available and can be applied as new grassroots production facilities are constructed. However, many existing hydroprocessing facilities, such as those using relatively low pressure hydrotreaters were constructed before these more stringent sulfur reduction requirements were enacted and represent a substantial prior investment. It is very difficult to upgrade existing hydrotreating reactors in these facilities because of the comparatively more severe operational requirements (i.e., higher temperature and pressure conditions) to obtain clean fuel production. Available retrofitting options for refiners include elevation of the hydrogen partial pressure by increasing the recycle gas quality, utilization of more active catalyst compositions, installation of improved reactor components to enhance liquid-solid contact, the increase of reactor volume, and the increase of the feedstock quality.
There are many hydrotreating units installed worldwide producing transportation fuels containing 500-3000 ppmw sulfur. These units were designed for, and are being operated at, relatively mild conditions, i.e., low hydrogen partial pressures of 30 kilograms per square centimeter for straight run gas oils boiling in the range of from 180° C. to 370° C.
However, with the increasing prevalence of more stringent environmental sulfur specifications in transportation fuels mentioned above, the maximum allowable sulfur levels are being reduced to no greater than 15 ppmw, and in some cases no greater than 10 ppmw. This ultra-low level of sulfur in the end product typically requires either construction of new high pressure hydrotreating units, or a substantial retrofitting of existing facilities, e.g., by integrating new reactors, incorporating gas purification systems, reengineering the internal configuration and components of reactors, and/or deployment of more active catalyst compositions. Each of these options represents a substantial capital investment
Sulfur-containing compounds that are typically present in hydrocarbon fuels include aliphatic molecules such as sulfides, disulfides and mercaptans, as well as aromatic molecules such as thiophene, benzothiophene and its alkylated derivatives, and dibenzothiophene and its alkyl derivatives such as 4,6-dimethyl-dibenzothiophene. Aromatic sulfur-containing molecules have a higher boiling point than aliphatic sulfur-containing molecules, and are consequently more abundant in higher boiling fractions.
In addition, certain fractions of gas oils possess different properties. The following table illustrates the properties of light and heavy gas oils derived from Arabian Light crude oil:
TABLE 1Feedstock NameLightHeavyBlending Ratio——API Gravity°37.530.5Carbonwt %85.9985.89Hydrogenwt %13.0712.62Sulfurwt %0.951.65Nitrogenppmw42225ASTM D86 DistillationIBP/5 V %° C.189/228147/24410/30 V %° C.232/258276/32150/70 V %° C.276/296349/37385/90 V %° C.319/330392/39895 V %° C.347Sulfur SpeciationOrganosulfur Compoundsppmw45913923Boiling Below 310° C.Dibenzothiophenesppmw10412256C1-Dibenzothiophenesppmw14412239C2-Dibenzothiophenesppmw13252712C3-Dibenzothiophenesppmw11045370
As set forth above in Table 1, the light and heavy gas oil fractions have ASTM D86 85 V % points of 319° C. and 392° C., respectively. Further, the light gas oil fraction contains less sulfur and nitrogen than the heavy gas oil fraction (0.95 wt % sulfur as compared to 1.65 wt % sulfur and 42 ppmw nitrogen as compared to 225 ppmw nitrogen).
Advanced analytical techniques such as multi-dimensional gas chromatography with a sulfur chemiluminescence detector as described by Hua, et al. (Hua R., et al., “Determination of sulfur-containing compounds in diesel oils by comprehensive two-dimensional gas chromatography with a sulfur chemiluminescence detector,” Journal of Chromatography A, Volume 1019, Issues 1-2, Nov. 26, 2003, Pages 101-109) have shown that the middle distillate cut boiling in the range of 170-400° C. contains sulfur species including thiols, sulfides, disulfides, thiophenes, benzothiophenes, dibenzothiophenes, and benzonaphthothiophenes, with and without alkyl substituents.
The sulfur speciation and content of light and heavy gas oils are conventionally analyzed by two methods. In the first method, sulfur species are categorized based on structural groups. The structural groups include one group having sulfur-containing compounds boiling at less than 310° C., including dibenzothiophenes and its alkylated isomers, and another group including 1-, 2- and 3-methyl-substituted dibenzothiophenes, denoted as C1, C2 and C3, respectively. Based on this method, the heavy gas oil fraction contains more alkylated di-benzothiophene molecules than the light gas oils.
In the second method of analyzing sulfur content of hydrocarbons, and referring to FIG. 1A, the cumulative sulfur concentrations are plotted against the boiling points of the sulfur-containing compounds to observe concentration variations and trends. Note that the boiling points depicted are those of detected sulfur-containing compounds, rather than the boiling point of the total hydrocarbon mixture. The boiling point of several refractory sulfur-containing compounds including dibenzothiophene, 4-methyldibenzothiophene and 4,6-dimethyldibenzothiophene are also shown in FIG. 1A for convenience. The cumulative sulfur specification curves show that the aromatic portion contains a higher proportion of heavier sulfur-containing compounds and a lower proportion of lighter sulfur-containing compounds as compared to the fraction containing primarily paraffins and naphthenes.
Aliphatic sulfur-containing compounds are more easily desulfurized (labile) using conventional hydrodesulfurization methods. However, certain highly branched aromatic molecules can sterically hinder the sulfur atom removal and are moderately more difficult (refractory) to desulfurize using conventional hydrodesulfurization methods.
Among the sulfur-containing aromatic compounds, thiophenes and benzothiophenes are relatively easy to hydrodesulfurize. The addition of alkyl groups to the ring compounds increases the difficulty of hydrodesulfurization. Dibenzothiophenes resulting from addition of another aromatic ring to the benzothiophene family are even more difficult to desulfurize, and the difficulty varies greatly according to their alkyl substitution, with di-beta substitution being the most difficult to desulfurize, thus justifying their “refractory” appellation. These beta substituents hinder exposure of the heteroatom to the active site on the catalyst.
The economical removal of refractory sulfur-containing compounds is therefore exceedingly difficult to achieve, and accordingly removal of sulfur-containing compounds in hydrocarbon fuels to an ultra-low sulfur level is very costly utilizing current hydrotreating techniques. When previous regulations permitted sulfur levels up to 500 ppmw, there was little need or incentive to desulfurize beyond the capabilities of conventional hydrodesulfurization, and hence the refractory sulfur-containing compounds were not targeted. However, in order to meet the more stringent sulfur specifications, these refractory sulfur-containing compounds must be substantially removed from hydrocarbon fuels streams.
The relative reactivity of thiols and sulfides are much higher than those of aromatic sulfur compounds, as indicated in a study published in Song, Chunshan, “An overview of new approaches to deep desulfurization for ultra-clean gasoline, diesel fuel and jet fuel” Catalysis Today, 86 (2003), pp. 211-263. Mercaptan/thiols and sulfides are much more reactive than the aromatic sulfur compounds. It should be noted that non-thiophenic sulfides such as paraffinic and/or naphthenic are present in diesel range hydrocarbons as seen from the chromatograph of FIG. 1B.
The development of non-conventional processes for desulfurization of petroleum distillate feedstocks has been widely studied, and certain conventional approaches are based on oxidation of sulfur-containing compounds described, e.g., in U.S. Pat. Nos. 5,910,440, 5,824,207, 5,753,102, 3,341,448 and 2,749,284.
Oxidation processes for heteroatomic compounds, such as oxidative desulfurization is attractive for several reasons. First, relatively mild reaction conditions, e.g., temperature from room temperature up to 200° C. and pressure from 1 up to 15 atmospheres, can often be used, thereby resulting a priori in reasonable investment and operational costs, especially compared to hydrogen consumption in hydroprocessing techniques which is usually expensive. Another attractive aspect of the oxidative process is related to the reactivity of aromatic sulfur-containing species. This is evident since the high electron density at the sulfur atom caused by the attached electron-rich aromatic rings, which is further increased with the presence of additional alkyl groups on the aromatic rings, will favor its electrophilic attack as shown in Table 2 (Otsuki, S. et al., “Oxidative desulfurization of light gas oil and vacuum gas oil by oxidation and solvent extraction,” Energy Fuels 14:1232-1239 (2000)). Moreover, the intrinsic reactivity of molecules such as 4,6-DMBT is substantially higher than that of DBT, which is much easier to desulfurize by hydrodesulfurization.
TABLE 2Electron Density of selected sulfur speciesSulfurElectronK (L/compoundFormulasDensity(mol.min))Thiophenol5.9020.270 Methyl Phenyl Sulfide5.9150.295 Diphenyl Sulfide5.8600.156 4,6-DMDBT5.7600.0767 4-MDBT5.7590.0627 Dibenzo- thiophene5.7580.0460 Benzo- thiophene5.7390.00574 2,5- Dimethyl- thiophene5.716— 2-methyl- thiophene5.706— Thiophene5.696—
Certain existing desulfurization processes incorporate both hydrodesulfurization and oxidative desulfurization. For instance, Cabrera et al. U.S. Pat. No. 6,171,478 describes an integrated process in which the hydrocarbon feedstock is first contacted with a hydrodesulfurization catalyst in a hydrodesulfurization reaction zone to reduce the content of certain sulfur-containing molecules. The resulting hydrocarbon stream is then sent in its entirety to an oxidation zone containing an oxidizing agent where residual sulfur-containing compounds are converted into oxidized sulfur-containing compounds. After decomposing the residual oxidizing agent, the oxidized sulfur-containing compounds are solvent extracted, resulting in a stream of oxidized sulfur-containing compounds and a reduced-sulfur hydrocarbon oil stream. A final step of adsorption is carried out on the latter stream to further reduce the sulfur level.
Kocal U.S. Pat. No. 6,277,271 also discloses a desulfurization process integrating hydrodesulfurization and oxidative desulfurization. A stream composed of sulfur-containing hydrocarbons and a recycle stream containing oxidized sulfur-containing compounds is introduced in a hydrodesulfurization reaction zone and contacted with a hydrodesulfurization catalyst. The resulting hydrocarbon stream containing a reduced sulfur level is contacted in its entirety with an oxidizing agent in an oxidation reaction zone to convert the residual sulfur-containing compounds into oxidized sulfur-containing compounds. The oxidized sulfur-containing compounds are removed in one stream and a second stream of hydrocarbons having a reduced concentration of oxidized sulfur-containing compounds is recovered. Like the process in Cabrera et al., the entire hydrodesulfurized effluent is subjected to oxidation in the Kocal process.
Wittenbrink et al. U.S. Pat. No. 6,087,544 discloses a desulfurization process in which a distillate feedstream is first fractionated into a light fraction containing from about 50 to 100 ppm of sulfur, and a heavy fraction. The light fraction is passed to a hydrodesulfurization reaction zone. Part of the desulfurized light fraction is then blended with half of the heavy fraction to produce a low sulfur distillate fuel. However, not all of the distillate feedstream is recovered to obtain the low sulfur distillate fuel product, resulting in a substantial loss of high quality product yield.
Rappas et al. PCT Publication WO02/18518 discloses a two-stage desulfurization process located downstream of a hydrotreater. After having been hydrotreated in a hydrodesulfurization reaction zone, the entire distillate feedstream is introduced to an oxidation reaction zone to undergo biphasic oxidation in an aqueous solution of formic acid and hydrogen peroxide. Thiophenic sulfur-containing compounds are converted to corresponding sulfones. Some of the sulfones are retained in the aqueous solution during the oxidation reaction, and must be removed by a subsequent phase separation step. The oil phase containing the remaining sulfones is subjected to a liquid-liquid extraction step. In the process of WO02/18518, like Cabrera et al. and Kocal, the entire hydrodesulfurized effluent is subject to oxidation reactions, in this case biphasic oxidation.
Levy et al. PCT Publication WO03/014266 discloses a desulfurization process in which a hydrocarbon stream having sulfur-containing compounds is first introduced to an oxidation reaction zone. Sulfur-containing compounds are oxidized into the corresponding sulfones using an aqueous oxidizing agent. After separating the aqueous oxidizing agent from the hydrocarbon phase, the resulting hydrocarbon stream is passed to a hydrodesulfurization step. In the process of WO03/014266, the entire effluent of the oxidation reaction zone is subject to hydrodesulfurization.
Gong et al. U.S. Pat. No. 6,827,845 discloses a three-step process for removal of sulfur- and nitrogen-containing compounds in a hydrocarbon feedstock. All or a portion of the feedstock is a product of a hydrotreating process. In the first step, the feed is introduced to an oxidation reaction zone containing peracid that is free of catalytically active metals. Next, the oxidized hydrocarbons are separated from the acetic acid phase containing oxidized sulfur and nitrogen compounds. In this reference, a portion of the stream is subject to oxidation. The highest cut point identified is 316° C. In addition, this reference explicitly avoids catalytically active metals in the oxidation zone, which necessitates an increased quantity of peracid and more severe operating conditions. For instance, the H2O2:S molar ratio in one of the examples is 640, which is extremely high as compared to oxidative desulfurization with a catalytic system.
Gong et al. U.S. Pat. No. 7,252,756 discloses a process for reducing the amount of sulfur- and/or nitrogen-containing compounds for refinery blending of transportation fuels. A hydrocarbon feedstock is contacted with an immiscible phase containing hydrogen peroxide and acetic acid in an oxidation zone. After a gravity phase separation, the oxidized impurities are extracted with aqueous acetic acid. A hydrocarbon stream having reduced impurities is recovered, and the acetic acid phase effluents from the oxidation and the extraction zones are passed to a common separation zone for recovery of the acetic acid. In an optional embodiment of U.S. Pat. No. 7,252,756, the feedstock to the oxidation process can be a low-boiling component of a hydrotreated distillate. This reference contemplates subjecting the low boiling fraction to the oxidation zone.
None of the above-mentioned references describe a suitable and cost-effective process for desulfurization of hydrocarbon fuel fractions with specific sub-processes and apparatus for targeting different organosulfur compounds. In particular, conventional methods do not separate a hydrocarbon fuel stream into fractions containing different classes of sulfur-containing compounds with different reactivities relative to the conditions of hydrodesulfurization and oxidative desulfurization. Conventionally, most approaches subject the entire gas oil stream to the oxidation reactions, requiring unit operations that must be appropriately dimensioned to accommodate the full process flow.
Aromatic extraction is an established process used at certain stages of various refinery and other petroleum-related operations. In certain existing processes, it is desirable to remove aromatics from the end product, e.g., lube oils and certain fuels, e.g., diesel fuel. In other processes, aromatics are extracted to produce aromatic-rich products, for instance, for use in various chemical processes and as an octane booster for gasoline.
U.S. Pat. No. 5,021,143 discloses a process in which a feed is fractionated into a light naphtha, a medium naphtha and a heavy naphtha. Aromatics are extracted from the heavy naphtha fraction using a selective liquid solvent, and the aromatic-lean raffinate is mixed with the kerosene or diesel pool. The aromatic-rich extract is regenerated by contacting with light petrol so as to produce an aromatic-rich petrol product.
U.S. Pat. No. 4,359,596 discloses a process in which aromatics are extracted from hydrocarbon mixtures such as isomerization process streams, catalytic cracking naphthas, and lube stocks. Liquid salts, such as quaternary phosphonium and ammonium salts of halides, acids or more complex anions are used as extraction liquids.
U.S. Pat. Nos. 4,592,832, 4,909,927, 5,110,445 5,880,325 and 6,866,772 disclose various processes for upgrading lube oils. In particular, these processes use various solvents to extract aromatics.
With the steady increase in demand for hydrocarbon fuels having an ultra-low sulfur level, a need exists for an efficient and effective process and apparatus for desulfurization. As far as the present inventors are aware, it has not previously been suggested to combine well-established aromatic extraction technology with desulfurization of hydrocarbon fuels, and in particular with integrated desulfurization including hydrotreating and oxidative desulfurization.
Accordingly, it is an object of the present invention to desulfurize and denitrify a hydrocarbon fuel stream containing different classes of sulfur-containing and nitrogen-containing compounds having different reactivities utilizing reactions separately directed to labile and refractory classes of sulfur-containing and nitrogen-containing compounds.
It is a further object of the present invention to produce hydrocarbon fuels having reduced sulfur and nitrogen levels by removal of labile organosulfur and organonitrogen compounds in a feedstream using hydrotreating under relatively mild conditions followed by targeted removal of refractory organosulfur and organonitrogen compounds using oxidation.
As used herein, the term “labile organosulfur compounds” means organosulfur compounds that can be easily desulfurized under relatively mild hydrotreating pressure and temperature conditions, and the term “refractory organosulfur compounds” means organosulfur compounds that are relatively more difficult to desulfurize under mild hydrotreating conditions. Likewise, the term “labile organonitrogen compounds” means organonitrogen compounds that can be easily denitrified under relatively mild hydrotreating pressure and temperature conditions, and the term “refractory organonitrogen compounds” means organonitrogen compounds that are relatively more difficult to denitrify under mild hydrotreating conditions.
Additionally, as used herein, the terms “mild hydrotreating” and “mild operating conditions” (when used in reference to hydrotreating) means hydrotreating processes operating at temperatures of 400° C. and below, hydrogen partial pressures of 40 bars and below, and hydrogen feed rates of 500 liters per liter of oil, and below.